A subsea pump, according to normal terminology in the art, is a pump designed to be operated as located on or close to the seabed. Accordingly, subsea pumping means pumping with subsea pumps arranged on or close to the seabed. In contrast, an Electric Submerged Pump (ESP) is according to normal terminology in the art a downhole pump to be arranged downhole into a wellbore for downhole pumping. Corresponding terminology can be used for compressors. Correspondingly, a subsea pressure booster is a subsea pump or compressor for subsea pressure boosting.
A demand exists for subsea pressure boosting for different applications.
Traditional subsea pumps are designed to handle rather large flow rates and high pressure boosting needs. Such pumps typically require supply of barrier fluid, extensive monitoring and manifold arrangements, making installations with such pumps complex, large, heavy and costly to fabricate and install.
For cases where there is a need to boost low flow rates, from a single well or a few wells, various attempts to applying downhole pumps—so called Electrical Submerged Pumps (ESP)—at the seabed have been tried. Such pumps have widespread application for artificial lift from wells as placed down in the wellbore. These pumps are driven by an electric motor powered through a cable clamped to the production tubing. They are mature machines with extensive track records, commercially available from a number of suppliers, Schlumberger and Baker Hughes being the biggest. Since they are designed to be placed in a slim well bore, they are long and skinny. Length can be up to 40 meter and total installed power can be up to and above 1 MW, typically about 20 m length and about 1 MW installed power.
One arrangement of placing ESPs on the seabed is described in U.S. Pat. No. 7,565,932, “Subsea flowline jumper containing ESP” by Baker Hughes Inc. The patent describes the basic concept of installing an ESP in a generally horizontal section of a flowline jumper. Such flowline jumpers are typically used to connect various units in a subsea production system, the flowline jumpers having a vertical connector in each end. By exchanging the horizontal pipe section of the flowline jumper with an enlarged section containing an ESP, ease of installation can be achieved.
In U.S. Pat. No. 7,516,795, “Subsea Petroleum Production System Method of Installation and Use of the Same”, by Petrobras, it has been described a subsea pumping system where pipe-mounted ESPs are assembled in a cassette. The ESPs are connected in series and mounted at an angle of up to 5 degrees from horizontal. The cassette is mounted onto a flow base. The cassette and the flow base can be installed via cable from service vessels in order to reduce time and cost.
Another arrangement is described in the U.S. Pat. No. 8,500,419 “Subsea pumping system with interchangeable pumping units”, by Schlumberger. This patent describes a similar arrangement of one or more ESPs in generally horizontal subsea pipe sections. Said patent describes a pumping module containing one or several pumping units mounted on a skid. The pump units, each having electric driven pumps (ESPs) assembled in a tubular section, can be individually retrieved. The pump skid includes a number of additional sub-systems: controller, sensor, pipe mount, hydraulic/electrical connectors, isolation valves and at least one fluid by-pass valve.
The U.S. Pat. No. 8,083,501 “Subsea pumping system including a skid with mate-able electrical and hydraulic connections”, also by Schlumberger, describes a more generalized version of the system described in patent U.S. Pat. No. 8,500,419. The two patents are filed at the same date. U.S. Pat. No. 8,083,501 has the same arrangement as U.S. Pat. No. 8,083,419, but describes a self-contained horizontal pump module, containing a centrifugal pump driven by an electrical motor. The description covers electric driven horizontal pumps in general—assembled in a pressure containing housing on a skid.
Pumps that are long and slim due to their intended application in a wellbore, are not ideal for subsea use. Typical subsea pumps are in contrast more compact and arranged for vertical installation and retrieval. A subsea pump is typically mounted on a flow base having a simple manifold arrangement for the routing of flow in and out of the pump plus allowing for by-pass in case of pump shutdown. U.S. Pat. Nos. 7,516,795, 8,500,419 and 8,083,501, mentioned above, describe typical subsea arrangement of the respective pumps mounted on a base. Such base is costly both to fabricate and install. Said pumps are arranged in a structure that adds weight and cost.
Subsea operations are expensive and equipment reliability is therefore one of the most vital selection criteria. Rotating equipment is in need of more frequent service than stationary equipment and reliability and serviceability should be given high priority in design.
ESPs have limited service life compared to subsea pumps, in part due to the design and in part due to the very challenging down-hole environment where they normally are installed. Typical interval for retrieval for service is 2-4 years.
However, if the arrangement described in the state of the art publication U.S. Pat. No. 7,565,932 could be further enhanced with respect to reliability, robustness, simplicity, cost and installation/retrieval, it would be beneficial for the petroleum industry and it would increase the use of ESPs subsea, on or close to the seabed.
The objective of the present invention is to improve the technology of the state of the art, as described in U.S. Pat. No. 7,565,932.